Various types of rotary drill bits, reamers, stabilizers and other downhole tools may be used to form a bore hole in the earth. Examples of such rotary drill bits include, but are not limited to, fixed cutter drill bits, drag bits, PDC drill bits and matrix drill bits used in drilling oil and gas wells. Cutting action associated with such drill bits generally requires weight on bit (WOB) and rotation of associated cutting elements into adjacent portions of a downhole formation. Drilling fluid may also be provided to perform several functions including washing away formation materials and other downhole debris from the bottom of a wellbore, cleaning associated cutting elements and cutting structures and carrying formation cuttings and other downhole debris upward to an associated well surface.
Fixed cutter rotary drill bits often have a bit body with a plurality of blades disposed on exterior portions of the bit body. Each blade typically includes a plurality of cutting elements or cutters disposed on exterior portions thereof. A gage pad may often be formed on each blade. Various types of compacts and cutting elements have sometimes been disposed within a gage pad. Cutting elements and/or compacts may sometimes be inserted into respective holes (not expressly shown) in exterior portions of a gage pad. Cutting elements disposed in such holes may sometimes be referred to as “drop in” cutting elements or cutters.
Gage pads typically cooperate with each other to define in part the largest outside diameter portion of an associated fixed cutter rotary drill bit. The gage pads may also define in part a nominal inside diameter of an associated wellbore formed by the fixed cutter rotary drill bit. At least one blade (and typically more than one blade) of prior fixed cutter rotary drill bits may often be formed with a significant gap or empty zone between the last cutting element on at least one blade and adjacent portions of an associated gage pad.
This gap may be formed because a typical cutter layout procedure usually starts with the first cutter disposed closest to bit center and towards the last cutter closest to the beginning of the associated gage pad following a specific overlapping rule. When the distance between the last cutter and the beginning of the associated gage pad is not big enough to fit another cutter, an empty zone or gap is typically formed on at least one blade.
Such gaps may have dimensions equal to or greater than corresponding dimensions of the last cutting element disposed on at least one blade. As a result, such gaps may leave partially uncut rings of formation material on the side wall of a wellbore formed by an associated rotary drill bit. For some applications noncutting elements such as tungsten carbide buttons or compacts may be placed within such gaps. For many straight hole drilling applications such noncutting elements may not interact with adjacent formation materials. However, for directional drilling, applications such noncutting elements may more frequently interact with the side wall of a wellbore because of side cutting action of an associated drill bit. The interaction of gage pads and noncutting elements with the side wall of a wellbore usually results in greater forces being applied to the associated drill bit as compared to forces applied to the bit when conventional cutting elements interact with adjacent formation materials. As a result, steerability of the associated drill bit may be significantly reduced.
Partially uncut rings of formation material may cause increased wear on gage pads of blades trailing a gap or noncontiguous cutting zone on at least one leading blade. Partially uncut rings of formation material may increase wear on exterior portions of at least one blade at the associated gap. Partially uncut rings of formation material may also reduce steerability of an associated fixed cutter rotary drill bit during directional drilling.
Various prior art references show examples of fixed cutter rotary drill bits having blades with a plurality of cutting elements or cutters disposed immediately adjacent to each other extending from an associated gage pad towards a bit rotational axis of an associated rotary drill bit. See for example, U.S. Pat. Nos. 5,607,024 and 5,265,685. Such cutting element layout procedure will often lead to 100% overlap, in a rotated profile, of the cutting elements having the same radial locations. As a result, uncut rings on the hole bottom may be formed which reduces significantly the rate of penetration and causes uneven wear of cutting elements. In addition, forming such rotary drill bits with cutting elements substantially covering all exterior portions of each blade extending from the associated gage pad may significantly increase costs associated with manufacturing such rotary drill bits. Also, placing a large number of cutting elements immediately adjacent to each other on exterior portions of an associated blade may be relatively difficult. Forming respective pockets or sockets in which each cutting element may be securely engaged generally takes up a significant amount of available space on each blade.